The present invention relates to sealant compositions used in subterranean operations, and more particularly, to cohesive sealant compositions and methods of use in subterranean operations.
Hydraulic cement compositions are commonly utilized in subterranean well completion and remedial operations. For example, hydraulic cement compositions are used in primary cementing operations whereby strings of pipe such as casing and liners are cemented in well bores. In performing primary cementing, a hydraulic cement composition is pumped into the annular space between the walls of a well bore and the exterior surface of the pipe string disposed therein. The cement composition is permitted to set in the annular space, thereby forming an annular sheath of hardened cement therein that provides a substantially impermeable hydraulic seal and substantially supports and positions the pipe string in the well bore and bonds the exterior surfaces of the pipe string to the walls of the well bore. As used herein, the term “hydraulic seal” is defined to include the ability to withstand a sufficiently high differential pressure across the sealant in the annulus or well bore as required for the operating envelope of the subject well. Such differential pressures may be caused by injected fluids, formation fluids, and the like. Hydraulic cement compositions also are used in remedial cementing operations such as plugging highly permeable zones or fractures in well bores, plugging cracks in holes in pipe strings, and the like. Hydraulic cement compositions are further used in permanently plugging well bores and isolating certain zones in conjunction with well abandonment. “Zone” as used herein simply refers to a portion of the formation and does not imply a particular geological strata or composition.
Set cement in wells, and particularly the set cement sheath in the annulus of a well, may fail due to, inter alia, shear and compressional stresses exerted on the set cement sheath. This may be particularly problematic in high temperature wells, which are wells wherein fluids injected into the wells, or produced from the wells by way of the well bore, cause a temperature change from initial cement setting conditions. In these types of wells, set cements often fail as a result of the stresses exerted on the set cement. In other types of wells the stresses are induced by movement of faults, or by a general subsidence of the terrain caused by reservoir pressure depletion upon production of hydrocarbons.
The stress exerted on the cement sheath as referred to herein means the force applied over an area resulting from the strain caused by the incremental change in length or volume. The stress is generally thought to be related to strain by a proportionality constant known as Young's Modulus. Young's Modulus is known to characterize the elasticity of a material. In a well bore sealing application, the Young's Modulus for a conventional 16.4 lb/gal cement sheath is about 3×106 lbf/in2, and for steel casings, the Young's Modulus is about 30×106 lbf/in2.
There are several stressful conditions that have been associated with well bore cement failures. One example of such a condition results from the relatively high fluid pressures and/or temperatures inside of the casing during testing, perforation, fluid injection, or fluid production. If the pressure and/or temperature inside the pipe increases, the resultant internal pressure expands the pipe. This expansion places stress on the cement sheath surrounding the casing causing it to crack, or the bond between the outside surface of the pipe and the cement sheath to fail in the form of, inter alia, loss of hydraulic seal. Another example of such a stressful condition is where the fluids trapped in a cement sheath thermally expand causing high pressures within the sheath/annulus itself. This condition often occurs as a result of high temperature differentials created during production or injection of high temperature fluids through the well bore, e.g., wells subjected to steam recovery processes or the production of hot formation fluids. Other stressful conditions that can lead to cement sheath failures include the forces exerted by shifts in the subterranean formations surrounding the well bore or other over-burdened pressures.
As the well parameters have become more challenging, the stresses imposed on the cement sheath have increased. For example, wells for producing hydrocarbon from a subterranean oil reservoir are often ultimately destroyed as a result of the movement of one or more subterranean rock formations penetrated by the well due to the subsidence of the formations. That is, when a large volume of hydrocarbon is produced from a subterranean reservoir by a well, one or more subterranean rock formations above the reservoir which are also penetrated by the well often subside, which causes movement of the formations transversely to the well bore. This may for example push the tubular to one side of the well bore, and/or move the tubular axially in the well bore, thereby inducing loads on the cement sheath and the tubular which can be detrimental. Hence such movement may eventually cause one or more portions of the rock formations to sever or crush tubular disposed in the well bore, thereby destroying the ability of the well to produce hydrocarbon through the well bore.
Stresses exerted on a cement sheath in the annulus can result in failure of the cement sheath as well as a breakdown of the bonds between the cement sheath and the pipe or between the cement sheath and the surrounding subterranean formations. Such failures can result in at least lost production, enviromnental pollution, hazardous rig operations, and/or hazardous production operations. A common result is the undesirable presence of pressure at the well head in the form of trapped hydrocarbon between casing strings. Additionally, cement sheath failures can be particularly problematic in multi-lateral wells, which include vertical or deviated (including horizontal) principal well bores having one or more ancillary, laterally extending well bores connected thereto.
Previous attempts to delay the well failure due to subsidence have involved drilling an oversized well bore through the rock formations expected to move using under-reaming techniques. Other efforts, as described in U.S. Pat. No. 5,787,983, issued to Heathman et al., involve cutting slots adjacent to the well bore in formations that are expected to move. With these techniques, casing is set uncemented in the well bore thereby leaving an additional annular space or slot around the casing. The existence of this space delays the destruction of the casing by one or more subsiding rock formations for a period of time depending upon the rates of movement of the subsiding formations. However, the space in the annulus does not provide a hydraulic seal for zonal isolation.
Recently, progress has been made to modify the properties of cement sheath used in primary cementing to better withstand the stresses from the well operations. However, some types of load cases, particularly those caused by subsidence, could impose stresses in excess of the maximum load bearing capacity of a conventional or modified cement system. In particular, modified cement slurries do not appear to solve these severe subsidence problems.